Interpretation of Permanent Well Monitoring Data to Improve Characterization of a Giant Oil Field

The Johan Sverdrup field located on the Norwegian Continental Shelf (NCS) started its production in October 2019. The field is considered as a pivotal development in the view of sustainable long-term production and developments on the NCS as well as creating jobs and revenue. The field is operated with advanced well and reservoir surveillance systems including Permanent Downhole Gauges (PDG), Multi-Phase Flow-Meters (MPFM) and seismic Permanent Reservoir Monitoring (PRM). This provides an exceptional basis for reservoir characterization and permanent monitoring. This study focuses on reservoir characterization to improve evaluations of sand permeability-thickness and fault transmissibility. Permanent monitoring of the reservoir with PDG / MPFM has provided an excellent basis for applying different methods of Pressure Transient Analysis (PTA) including analysis of well interference and time-lapse PTA. Interpretation of pressure transient data is today based on both analytical and numerical reservoir simulations (fit-for-purpose models). In this study, such models of the Johan Sverdrup reservoir regions have been assembled, using geological and PVT data, results of seismic interpretations and laboratory experiments. Uncertainties in these data were used to guide and frame the scope of the study. The interference analysis has confirmed communication between the wells located in the same and different reservoir regions, thus revealing hydraulic communication through faults. Sensitivities using segment reservoir simulations of the interference tests with different number of wells have shown the importance of including all the active wells, otherwise the interpretation may give biased results. The estimates for sand permeability-thickness as well as fault leakage obtained from the interference analysis were further applied in simulations of the production history using the fit-for-purpose reservoir models. The production history contains many pressure transients associated with both flowing and shut-in periods. Time-lapse PTA was focused on extraction and history matching of these pressure transients. The simulations have provided reasonable match of the production history and the time-lapse pressure transients including derivatives. This has confirmed the results of the interference analysis for permeability-thickness and fault leakage used as input for these simulations. Well interference is also the dominating factor driving the pressure transient responses. Drainage area around the wells is quickly established for groups of the wells analyzed due to the extreme permeability of the reservoir. It was possible to match many transient responses with segment models, however mismatch for some wells can be explained by the disregard of wells outside the segments, especially injectors. At the same time, it is a useful indication of communication between the regions. The study has improved reservoir characterization of the Johan Sverdrup field, also contributing to field implementation of combined PTA methods.

An Overview of the Numerical Approaches to Water Hammer Modelling: The Ongoing Quest for Practical and Accurate Numerical Approaches

Here, recent developments in the key numerical approaches to water hammer modelling are summarized and critiqued. This paper summarizes one-dimensional modelling using the finite difference method (FDM), the method of characteristics (MOC), and especially the more recent finite volume method (FVM). The discussion is briefly extended to two-dimensional modelling, as well as to computational fluid dynamics (CFD) approaches. Finite volume methods are of particular note, since they approximate the governing partial differential equations (PDEs) in a volume integral form, thus intrinsically conserving mass and momentum fluxes. Accuracy in transient modelling is particularly important in certain (typically more nuanced) applications, including fault (leakage and blockage) detection. The FVM, first advanced using Godunov’s scheme, is preferred in cases where wave celerity evolves over time (e.g., due to the release of air) or due to spatial changes (e.g., due to changes in wall thickness). Both numerical and experimental studies demonstrate that the first-order Godunov’s scheme compares favourably with the MOC in terms of accuracy and computational speed; with further advances in the FVM schemes, it progressively achieves faster and more accurate codes. The current range of numerical methods is discussed and illustrated, including highlighting both their limitations and their advantages.

Stress field orientation controls fault leakage at a natural CO₂ reservoir

Travertine deposits at the St. Johns Dome natural CO2 reservoir in Arizona, USA, document a long (> 400 ka) history of surface leakage of CO2 from a subsurface reservoir. Travertine deposits are concentrated along surface traces of faults implying that there has been a structural control on the migration pathway of CO2 rich fluids. Here, for the first time, we combine slip tendency and fracture stability to analyse the geomechanical stability of the reservoir-bounding Coyote Wash Fault for three different stress fields and predict areas with high leakage risks. We find that these areas coincide with the travertine deposits on the surface indicating that high permeability pathways as a result of critically stressed fracture networks exist in both fault damage zones and around a fault tip. We conclude that these structural features control leakage. Importantly, we find that even without in-situ stress field data the known leakage points can be predicted using geomechanical analyses, despite the complex tectonic setting. Thus, even though acquiring high quality stress field data for secure subsurface CO2 or energy storage is a must, a first order assessment of leakage risks during site selection can be made with limited stress field knowledge.

Key controls on hydrocarbon retention and leakage from structural traps in the Hammerfest Basin, SW Barents Sea: implications for prospect analysis and risk assessment

Evidence of hydrocarbon leakage has been well documented across the SW Barents Sea and is commonly associated with exhumation in the Cenozoic. While fault leakage is thought to be the most likely cause, other mechanisms are possible and should be considered. Further study is required to understand what specific mechanism(s) facilitate such leakage, and why this occurs in some locations and not others. In a case study of the Snøhvit Field, we use seismic and well data to quantify fault- and top-seal strength based on mechanical and capillary threshold pressure properties of fault and cap rocks. Magnitude and timing of fault slip are measured to acknowledge the role that faults play in controlling fluid flow over time. Results based on theoretical and in situ hydrocarbon column heights strongly indicate that across-fault and top-seal breach by capillary threshold pressure, and top-seal breach by mechanical failure are highly unlikely to have caused hydrocarbon leakage. Instead, top-seal breach caused by tectonic reactivation of identified faults is likely to have facilitated hydrocarbon leakage from structural traps. The results of this case study acknowledge the different mechanisms by which hydrocarbons can leak from a structural trap. Employing both a holistic and quantitative approach to assessing different seal capacities reduces the likelihood that a particular cause of hydrocarbon leakage is overlooked. This is particularly relevant for the Snøhvit Field in its dual capacity as a producing gas field and as a carbon sequestration site since both systems rely on a thorough understanding of seal capacity and leakage potential.